Recovery of hydrocarbons using electrical stimulation

ABSTRACT

A method of recovering hydrocarbon such as heavy oil or bitumen from an underground oil-rich reservoir formation such as oil sand or oil shale is provided. One or more substantially vertical wells are drilled into the formation so that the bottom portion of each well extends into the formation and, preferably, below the bottom of the formation. The bottom portion of each well may be enlarged relative to the rest of the well. The bottom portion of the well is substantially filled with conductive liquid, sealed at the surface and high voltage power of up to 72,000 Volts or more is applied via an electrical conductor having an electrode submerged in the conductive liquid. The resulting current flow increases the formation temperature, causing the heavy oil or bitumen to flow from the formation into the bottom portion where it can be removed from the well.

CROSS REFERENCE TO RELATED APPLICATIONS

This application claims priority benefit from U.S. Provisional Patent Application No. 60/596,390 filed Sep. 20, 2005.

FIELD OF THE INVENTION

This invention relates generally to a method of recovering hydrocarbons such as bitumen from underground formations. More particularly, this invention relates to a method of recovering hydrocarbons by drilling one or more substantially vertical wells in the formation and applying high voltage electrical power directly to the formation via said wells to increase the temperature and/or pressure in the formation. The heated hydrocarbon such as bitumen readily flows to a production cavity in the well and is elevated to the surface through the well using the high pressure created within the formation.

BACKGROUND OF THE INVENTION

Over the past several years, there has been much advancement in thermal processes applied for recovering heavy, viscous oil (e.g., bitumen) from subterranean reservoirs such as oil sand reservoirs, oil shale reservoirs and the like. The most popular method used today to extract bitumen from underground formations is Steam Assisted Gravity Drainage (SAGD) and its variations.

SAGD extraction involves the injection of steam into the formation through parallel pairs of wells drilled down to the formation and then direction drilled horizontally for about 1,000 meters. The horizontally drilled top well is used for steam injection, and the horizontally drilled lower well, generally 5-8 meters below, is used as the production well. As the formation is heated by the steam injection, the heated bitumen begins to flow downward towards the lower well. Once communication is established between the two wells, the bitumen-steam emulsion flows downward by gravity, into the lower well, along with silt, condensate, and brackish water. The pressure created by the steam forces the liquid slurry through a production pipe upward to the surface.

However, there are several problems that one encounters when employing SAGD for bitumen extraction. Some of the drawbacks to using SAGD are as follows:

-   -   1. Multiple boilers are needed to produce the steam;     -   2. A continual large volume of fresh water is required for         making steam;     -   3. Large volumes of Natural Gas are required to fire the         boilers;     -   4. Condensate returning from the underground is heavily         contaminated;     -   5. Condensate recovery uses large volumes of chemicals for water         treatment;     -   6. Steam injection into the formation produces a less desirable         liquid-oil-clay slurry;     -   7. Steam injection disturbs the formation, causing silt and sand         washout;     -   8. Boiler operators are required round-the-clock to operate the         steam boilers;     -   9. Boiler maintenance is high from corrosive and dirty         condensate used in the boilers;     -   10. Contaminated water disposal is an environmental issue;     -   11. The formation temperature rise is limited by the operating         design temperature of the boilers and the final temperature of         the steam arriving at the formation;     -   12. The formation heat-up time using steam is considered to be a         slow process needing improvement;     -   13. Steam may produce a lower formation temperature, resulting         in a lower bitumen recovery rate than other sources of heat such         as electric power;     -   14. The costs associated with using remotely generated steam may         be higher than if heat were supplied by electrical power         directly into the formation; and     -   15. SAGD methods are believed to be limited to about 2000 ft in         the depth from which recovery may most economically be realized.         The present invention may be used in depths to 4,000 ft or more,         thereby opening access to the deep bitumen formations for the         first time. The present invention does not need to generate its         heat at the surface, but generates its heat directly within the         deep formation.

Another method tried in the past, without much commercial success, uses low voltage power (under 15,000 Volts) applied through vertical and parallel drilled cased wells, where the casing extended down into the formation. However, problems were also encountered with this method, including:

-   -   1. Evaporation of the conductive water occurred around the         drilled hole as the temperature of the pipe increased above         evaporation temperature;     -   2. Excess heat concentrated around the drill hole where the         electrical current was most dense, increased evaporation of the         liquid;     -   3. Electric pumps were required to pump the bitumen from the         formation to the surface;     -   4. Energy losses through the pipe casing, which conducted the         electrical current from the surface to the formation, caused         much of the energy to be absorbed by the pipe before it got to         the formation. This reduced energy efficiency. It also limited         the quantity of power reaching the formation;     -   5. The electrical voltage was applied at a predetermined maximum         conductivity point within the formation. This method failed to         capture the much larger conductivity that existed by paralleling         all the conductivities throughout the formation;     -   6. There is a misconception within the industry that electrical         energy created from steam could not be as efficient as using         steam directly to heat the formation thereby limited electrical         effort using electrical power as the main heat source;     -   7. Low voltages used to date could not viably transmit the         required large power needs into the formation without using         closely spaced, numerous drill holes, making such installations         uneconomical. Low voltage needs high current to transmit large         power loads into the formation, a limiting factor in earlier         experiments;     -   8. There is a problem with sand/silt accumulations seriously         interfering with bitumen extraction through SAGD pipes; and     -   9. The overall electrical efficiency from the electrical energy         methods tried in past proved to be less efficient than that         achieved using steam.

The present invention provides a method for electrically heating the hydrocarbon within the formation while overcoming one or more of the above-mentioned limitations found in the prior art.

SUMMARY OF THE INVENTION

In one aspect, the present invention provides a method for recovering hydrocarbons such as heavy oil or bitumen from an underground oil-rich reservoir formation, including:

-   -   providing one or more substantially vertical wells, each well         having a bottom portion extending into the oil-rich reservoir         formation and each well spaced apart from one another;     -   adding to each well a conductive liquid to substantially fill         the bottom portion of each well;     -   inserting an electrical conductor comprising an electrode into         each well so that the electrode is at least partially submerged         in the conductive liquid;     -   applying electrical power to the electrical conductor at a         voltage sufficient to heat the conductive liquid and the         oil-rich reservoir formation to a temperature sufficient to heat         the heavy oil or bitumen in the oil-rich reservoir formation;         and     -   substantially sealing the top of each well to maintain a         sufficiently high pressure in each well to prevent evaporation         once saturation temperature is reached and to force the heated         heavy oil or bitumen to flow into the bottom portion of the well         and through the well to the surface of the well.

In another aspect, the present invention provides a method for recovering hydrocarbons such as heavy oil or bitumen from an underground oil-rich reservoir formation, including:

-   -   providing one or more substantially vertical wells, each well         having a bottom portion extending into the oil-rich reservoir         formation and each well being lined with a casing;     -   inserting a production tubing into each well, said production         tubing extending at least partially into the bottom portion of         said well;     -   adding to each well a conductive liquid to substantially fill         the bottom portion of each well;     -   inserting through the production tubing an electrical conductor         comprising an electrode so that the electrode is at least         partially submerged in the conductive liquid;     -   applying electrical power to the electrical conductor at a         voltage sufficient to heat the conductive liquid and the         oil-rich reservoir formation to a temperature sufficient to heat         the heavy oil or bitumen in the oil-rich reservoir formation;         and

substantially sealing the top of each well to maintain a sufficiently high pressure in each well to prevent evaporation once saturation temperature is reached and to force the heated heavy oil or bitumen to flow into the bottom portion of the well and through the production tubing to the surface of the well.

In one embodiment, the conductive liquid comprises an electrolyte selected from the group consisting of sulfates, nitrates, acetates, oxalates, bitterns, bromides, and any combinations thereof. As is commonly practiced in the art, the conductive liquid is usually first tested in the lab to determine its potential corrosion on in-situ extraction equipment and upstream process equipment and less corrosive conductive liquids are selected.

In one embodiment, the voltage ranges from between about 13,000 Volts to about 72,000 Volts, or higher. In another embodiment, the temperature of the oil-rich reservoir formation is between about 100° C. to about 300° C. or higher. In yet another embodiment, the pressure in each well is between about 0.1 MPa to about 6.9 MPa or higher.

In a preferred embodiment, the bottom portion of each well is enlarged relative to the rest of the well. In a further preferred embodiment, a wetting agent, such as those used in photographic film development, is added to the conductive liquid to allow full and intimate contact between the conductive liquid and the heavy oil or bitumen, thereby enhancing conductivity in the formation.

In a further preferred embodiment, the production tubing is moveable so that it can be raised or lowered within the well to suit operating needs.

In another embodiment, any gas that has accumulated in the top portion of the production cavity, just under the casing, may be removed separately from the well, if so desired. This is achieved by simply opening on of the valves on the surface casing and allowing the formation pressure to push the gas out to a collection line. The higher formation operating temperatures opens up a wide range of gas compositions which will be generated, and it may be desirable to extract this gas.

In another embodiment, the electrical conductor further comprises an insulation jacket suitable for the operating voltage and temperature.

In a preferred embodiment, the surface of the operating site undergoes various preparations known in the art to minimize voltage gradient, surface runoff water penetration, and conductivity, so that energy losses and unsafe conditions are minimized.

In one embodiment, the underground oil-rich reservoir formation is oil sand or oil shale.

Without being bound by theory, it is thought that one or more of the following factors may be important in the operation of the invention.

It is believed that an initial power input through the formation is established by being able to apply high voltage between the wells, using the thin “hydrophilic film” surrounding each bitumen-encased grain of sand as the main initial conductive path. High voltage allows spacing between wells of about 20 to about 200 meters or more, thereby greatly reducing drilling costs and surface environmental disturbance. High voltage also allows large power input at low currents, avoiding the input conductor heating problems encountered by other systems.

It is expected that, as the formation is heated, the hydrophilic film around each sand grain will evaporate or dissipate, thereby increasing the conductivity of the formation such that the power input will be reduced. The present invention attempts to minimize the above-mentioned undesirable situation where conductivity may be reduced or lost if the hydrophilic film is drained away before another conductive path is established.

One of the functions of the production cavity is to heat the conductive liquid surrounding the electrode, which in turn heats the bitumen within the wall of the cavity. The heated bitumen slowly begins to flow from the wall of the cavity, rising up to the top of the hot conductive liquid within the cavity. The displaced bitumen is then replaced with the conductive liquid from the production cavity. Thus, as time progresses and the formation around the cavity continues to heat up and the bitumen continues to float up to the top of the conductive liquid, the conductive liquid gradually and very positively moves into the formation. Hence, by heating the formation from outside first, and then gradually heating towards the center, the cooler central portion of the formation will maintain conductivity through the hydrophilic film until the conductive liquid from the cavity has advanced enough to maintain the conductivity of the formation, partly through the hydrophilic film and increasingly more through the conductive liquid.

In the present invention, the production cavity maintains the highest temperature. Within the surrounding formation, the current density and applied unit power are a very small fraction of current density existing at the production cavity wall. This is thought to be important for maintaining communication between the widely spaced wells. If the temperature were to rise prematurely within the formation, there is a danger of losing communication between wells. A high temperature would break down the hydrophilic film and cause the conductivity between wells to drop to levels that may not allow enough energy to flow into the formation to meet minimum economic production. Thus, the production cavity is maintained at a higher temperature, allowing the gradual displacement of heated bitumen surrounding the cavity to be replaced by the conductive liquid. Ultimately, as the formation heats, the conductivity from the disappearing hydrophilic film will be replaced by the advancing layer of conductive liquid from the refilled production cavity.

It is believed that the production cavity serves as a sump into which the bitumen flows as it leaves the formation. In one embodiment of the present invention, the production tubing may be lowered or raised to selectively extract the bitumen that has slowly separated from the conductive liquid, brine, and silt within the production cavity. In another embodiment, the well itself is used to lift the separated bitumen to the surface, powered by the created pressure within the formation.

The production cavity may also serve as a sump to hold sand and silt which falls from the sidewalls of the cavity as bitumen flows gently from the formation. Ultimately the sand and silt will build up to reduce the effective cavity working volume. This build-up is expected to continue till the slope of the cavity sidewalls are at a 10-40 degree angle of repose, after which time the build-up will be minimal. The sand and silt may be removed from the cavity by lowering the production tubing close to the bottom of the cavity and forcing the sand and silt through the production tubing on to the surface. By enlarging the diameter of the production cavity and extending the bottom of the sump some distance below the formation, it is expected that the sand and silt build-up falling from the side walls of the cavity may fill the sump only to the bottom of the formation. This would thereby avoid the need to remove the sand/silt accumulation.

Ideally, the production cavity and formation are held at a pressure above the boiling point of the liquids within the cavity. The higher pressure prevents the liquids from boiling, and allows operating temperatures to be held at up to 300° C. or more as desired for maximum production and resource recovery.

The electrode added to the end of the conductor increases the area through which the electrical current flows from the conductor by 5-10 times or more, thereby reducing the watt density at the electrode. The heated electrode surrounded by the conductive liquid is further cooled from the circulating current of water rising up along the surface of the hot electrode, eliminating hot spots on the electrode. The cooler electrode reduces the undesirable tendency to have the bitumen bake onto the electrode, thereby avoiding the creation of a baked-on carbon insulated layer. This layer, if allowed to build up, reduces the conductivity of the electrical circuit and reduces power input into the formation. The electrode may be coated or plated with a non-corrosive material such as platinum to reduce or eliminate electrode corrosion from passage of electrical current and from exposure to corrosive liquid.

By varying the conductive liquid and bitumen level within the production cavity, the resistance to current flow may be varied. For example, by raising the conductive fluid level within the cavity, the number of varying resistance layers remaining in parallel through the formation increases. This reduces the overall formation resistance. It is thought that this is achieved by the law of “parallel resistance”, which decreases the total resistance as more of the varying formation resistance levels are put in parallel. Conversely, by dropping the conductive liquid level in the production cavity, less resistance layers remain in parallel, thereby increasing the resistance of the formation. This is one method to control the level of power flowing in the formation. Another method of controlling the power into the formation is by partially removing the conductive liquid from one or more production cavities, cleaning it to remove the conductive minerals and impurities, and then reinserting it back into the cavity. This makes the cavity and conductive liquid less conductive to match the power input requirements of the operation. Other power varying methods are possible using tap changers on Variable Voltage Power Transformers, Voltage regulators; Variable frequency drives for higher or lower frequencies; etc.

When the present invention is coupled with existing SAGD type installations, one would expect to increase the temperature within the formation between well pairs, and allow greater production output and higher resource recovery rates. Thus, the present invention may be applied directly through the existing SAGD production/injection pipes, once suitably isolated for safety. Again, the conductive liquid would need to be injected through the SAGD pipes directly into the SAGD cavity to provide intimate contact with the formation. Typically, the SAGD pipe pairs are separated by about 150 meters or so. When each pipe-pair has been flooded with conductive liquid, and up to 75,000 volts or more is applied between the SAGD pipes, a current will be established and will gradually increase as the conductive liquid displaces the heated bitumen. The temperature and pressure around the SAGD pipes will increase as power increases, and now the top injection pipe becomes the production pipe. Gradually the total formation will be heated between the SAGD pipe pairs, which are separated by up to 150 meters or more.

The use of electrical energy is as cheap as or cheaper than the use of steam for in-situ bitumen formation heating for the reasons now following. First, electrical energy is produced in very large power boilers using full energy recuperation, full and pure condensate recovery, with little treatment required. This provides an advantage when compared to the small industrial boilers now used for steam injection, with minimal energy recuperation, and with condensate recovered from a sludge mixture of silt, sand, brackish water, and bitumen products, all recovered from the formation. This is not favorable for high efficiency steam generation.

Second, the large power boilers use multi-pass heat recovery, thereby achieving the highest possible level of energy recovery. This provides an advantage when compared with the small SAGD boilers which only partially recover the injected steam which must flow several thousand meters through un-insulated lines to and from the formation, where a single pass heat recovery is only partially achieved.

Third, the very large power boiler controls and boiler cleansing technology are the most efficient known today. This provides an advantage when compared with the industrial controls and dirty boiler tubes resulting from using highly treated production-recovered-water taken from the brackish bitumen formation.

Fourth, electrical energy is applied directly within the formation, with negligible transmission losses. This provides an advantage when compared with steam transported several thousand meters mostly through un-insulated pipes to get to the formation, and then the return of the highly contaminated condensate a similar distance back to the water treatment and recovery plant then on to the surface boilers.

Fifth, electrical power may be transmitted to site at a cost comparable to the power transmission costs already incurred to power SAGD needs. This provides an advantage when compared with Natural Gas and the fresh boiler-feed-water pipelines, which must be constructed long distances to get to the SAGD site. SAGD also requires electrical power to be brought to site where a large quantity of electricity is needed to run the boiler fans, pumps, and water treatment equipment.

Sixth, “Off-Peak” power, not mentioned in electrical in-situ power comparisons, can be used at a price reduction of 20-40% for much of the energy needs. This is possible because of the large heat sink created within the formation. Power may be cut off and easily restored as desired by the power company, thereby allowing “Peak-Power” periods to be bypassed. This feature alone makes electrical power cheaper than SAGD steam energy.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is an illustration of one arrangement of a well of the present invention prior to electrical power being applied to the electrical conductor.

FIGS. 2 a to 2 e are sequential illustrations showing the progressive changes in the well and surrounding oil-rich reservoir formation of FIG. 1 after electrical power has been applied to the electrical conductor.

FIG. 3 shows one embodiment of the surface arrangement with seals, packing glands, main shut-off valve, and other valves and operating indicators.

FIG. 4 illustrates two adjacent wells extending down from the surface to an oil-rich reservoir formation.

FIG. 5 a illustrates a three dimensional field arrangement of a typical multi-well production unit.

FIG. 5 b illustrates in cross-section the field arrangement of FIG. 5 a

FIG. 6 illustrates the electrical current path of the three-phase arrangement of wells in FIGS. 5 a and 5 b.

FIG. 7 illustrates one embodiment of a surface distribution layout of a plurality of multi-well production units of the present invention.

DESCRIPTION OF THE PREFERRED EMBODIMENT

An embodiment of the present invention will be described with particular reference to tar or oil sand formations.

FIG. 1 illustrates a typical arrangement of a well before electrical power is applied to the formation. Wellbore 10 extends through overburden 14 and into oil (tar) sand formation 12. The bottom portion of wellbore 10 comprises an enlarged production cavity 16 and the walls 18 of production cavity 16 are substantially vertical. In the present embodiment, the well further comprises casing 30 and production pipe or tubing 28, which tubing extends partially into production cavity 16 and through which the conductive liquid 26 is added to the production cavity 16. When bitumen is ultimately produced, the bitumen flows to the surface through production tubing 28. The casing 30 may be insulated from the electrical conductor 32 by suitable insulation as is known in the art (not shown) in order to operate at the voltage and temperatures necessary for the present invention.

Surrounding production cavity 16 is oil sand formation 12 comprised of unheated bitumen 20 holding sand 24 and rock 22 in place. Production cavity 16 is initially filled with conductive liquid 26, which is unheated, and as such has not started entering into the formation 12, other than where indigenous streams of brackish water may exist. A space 37 is left between the surface 36 of the conductive fluid 26 and the top of the production cavity 16, which space will accumulate gas and steam as the bitumen extraction process proceeds as shown in FIGS. 2 a to 2 e. At this initial stage, negligible bitumen will have separated from the formation to rise to the surface of the conductive fluid in the production cavity at this time.

Electrical conductor 32 is inserted through production tubing 28 and extends into conductive liquid 26. Attached to electrical conductor 32 is electrode 34, which is shown as being fully submerged in conductive liquid 26. The power source may be single or three-phase AC, or it may be High Voltage DC. It may also be of a frequency other than the standard 60 Hertz.

In the example well shown in FIG. 1 and prior to practicing the invention, the pressure in productive cavity 16 is about 0.0 MPa, the temperature of conductive liquid 26 is around 25° C. and the temperature of oil sand formation 12 is around 27° C. In general, the oil sand formation will have a temperature of approximately 25° C. to about 40° C., depending on formation depth.

FIGS. 2 a to 2 e sequentially illustrate the progressive changes in the well and surrounding oil sand formation after electrical power is applied and the wellbore sealed to withstand the resulting pressure generated by the temperature rise in the cavity and formation (see FIG. 3 and discussion below).

With reference first to FIG. 2 a, the enlarged production cavity 16 is slowly being heated via conductive liquid 26 as a result of electrical power being applied to the electrode 34, which flows through the conductive liquid 26 and on through the oil sand formation 12. As previously mentioned, conductive liquid 26 comprises one or more electrolytes and, optionally, a wetting agent. The surface valve 52 (shown in FIG. 3) is closed at this point. The pressure in production cavity is slowly rising to 0.1 MPa and when the temperature of the conductive liquid reaches about 100° C., the temperature of the oil sand reservoir heats up to about 85° C. to about 90° C.

FIG. 2 b illustrates the conductive liquid 26 reaching about 150° C. and the oil sand formation 12 near the production cavity 16 also rising in temperature (shown as being between about 130-140° C.). The bitumen 20 is now softening due to the heat addition in the formation and slowly begins to flow upward along the production cavity walls 18 to the surface 36 of the conductive liquid 26. The conductive liquid 26 immediately replaces the void created in the oil sand formation 12 as a result of the bitumen 20 flowing up to the top of the production cavity 16. As the temperature of the conductive liquid 26 exceeds 100° C., some of the water therein begins to boil and vaporize into steam. Slowly, the steam pressure and temperature increases within the cavity and production pipe until the saturation level is reached. Further, as heating continues, saturation temperatures and pressures continue to rise (e.g., at this stage the pressure in the production cavity 16 would be about 0.38 MPa).

As electrical power continues to be applied, FIG. 2 c illustrates the temperature of the production cavity 16 increasing to about 200° C., the pressure rising to 0.85 MPa, and bitumen 20 flowing from the most conductive layers in the oil sand formation 12 where the greatest heat is applied into the production cavity 16. The conductive liquid 26 is now moved further into the oil sand formation 12 and is replaced by bitumen 20, which rises to the surface 36 of conductive liquid 26.

FIG. 2 d illustrates the commencement of bitumen 20 recovery. The valve 52 on the production tubing located at the surface (as shown in FIG. 3) is opened, thereby relieving the pressure at the top of the production tubing and causing the bitumen to flow upward to the surface through production tubing 28. The bitumen flow 21 will continue as long as the surface valve 52 is open and the production cavity pressure is maintained at a level higher than the hydrocarbon head in the production tubing 28 (e.g., about 3.9 MPa).

FIG. 2 e illustrates bitumen production when the production cavity temperature reaches 300° C. temperature. It is expected that temperatures of 325° C. or more may be possible, depending on the ability of the formation to withstand the pressure. Further, the pressure rises and reaches about 6.9 MPa or more. The electrical power used to create the temperature and pressure within the formation is not limited by any mechanical equipment other than the seals at the surface that keep the pressure from escaping.

It can be seen in FIG. 2 e that the production cavity has gotten much larger at this point and the space 37 between the surface of the bitumen 20 accumulating on the surface 36 of the conductive fluid 26 and the top of the production cavity 16 is filled with gas and steam. The bitumen 20 accumulating at the surface 36 of the conductive fluid 26 is continuously removed through the production tubing 28. It is understood that the production tubing 28 can be raised or lowered to accommodate the removal of the bitumen 20. Optionally, the gas/steam that accumulates in space 37 can also be removed from the wellbore and separately recovered through production tubing.

It is possible that at certain temperatures and pressures there may be a bitumen-conductive water density inversion, thereby causing the water to float on top of the bitumen. For example, there may be one or two inversions occurring during the practice of the present invention as the temperature and pressure increases. It is understood that if such an inversion occurs, the production tubing elevation and conductive liquid levels will then need to be adjusted to allow the desired bitumen recovery.

FIG. 3 shows one embodiment of the surface arrangement for sealing the wellbore during operation of the invention in order to withstand the resulting pressure generated by the temperature rise in the cavity and formation. The contained high pressure achieved in the present invention prevents the liquid from evaporating once saturation temperature is reached. Thus, as power increases into the formation, the resulting temperature and pressure rise are limited only by the competence of the formation. Formation temperatures of about 275-300° C. or more are therefore achievable.

Surface wellhead arrangement 50 is comprised of various seals, packing glands 54 and main shut-off valve 52. Valve 51 is used for bitumen removal, valve 53 for delivering conductive liquid to the wellbore and valve 55 is used for clean out, as required. Pressure gauge 56 monitors the pressure in the well and temperature gauge 57 monitors the temperature in the well.

Thus, the liquid evaporation problem of concern in earlier electrical power recovery methods is overcome by sealing the wellbore with surface wellhead arrangement 50 to withstand the resulting pressure generated by the temperature rise in the cavity and formation. It is understood, however, that other surface well control devices as known in the art may be used.

Thus, the surface wellhead arrangement 50 is adapted to allow the electrical conductor 32 to enter the wellbore and be positioned in the production cavity. The surface wellhead arrangement 50 also allows the production tubing to extract the bitumen without losing formation pressure through valve 51. The surface wellhead arrangement 50 further allows the conductive liquid to be added or removed from the formation while retaining the formation pressure through valve 53.

The arrangement 50 allows the electrical conductor 32 to be raised or lowered as required. For example, the main shut-off valve 52 can be used to close off the well when the electrical conductor 32 is removed for maintenance or replacement, to maintain the well pressure. The surface wellhead arrangement 50 also allows the production tubing to be raised or lowered as required.

FIG. 4 illustrates two adjacent wells, 62 and 64, respectively, extending down from the surface 60 to the oil sands formation 12 to illustrate the establishment of communication between adjacent wells. Both wells 62 and 64 are enlarged at the bottom to form respective production cavities 16, which cavities extend through the oil sand formation 12 and for several meters below formation 12. Each well comprises production tubing 28 through which electrical conductor 32 passes from the surface to the formation into the respective production cavities 16, which are filled with conductive liquid 26. Electrode 34 is attached to each conductor 32 and is suspended at any desired level within the formation production cavity. The wellhead arrangement 150 is shown in one of the many configurations and is used to seal the wells 62 and 64 during operation of the present invention. Each well is sealed to withstand the highest operating pressures that may be used.

It can be seen in FIG. 4 that electrical communication between adjacent wells is established. Electrical current 66 flows between the two electrodes 34 of wells 62 and 64, thereby accelerating the heating of the oil sand formation 12 therebetween. This allows for more efficient heating of the bitumen in the formation.

FIG. 5(a) shows a three-dimensional field arrangement of a typical production unit comprising a plurality of wells 70, 72, 74 and 76 and FIG. 5 b shows such a unit in cross-section. The three-phase, four-wire power payout is shown consisting of Phase A (well 70), Phase B (well 76), Phase C (well 72) and the fourth wire which is the Neutral (well 74). This arrangement is a very familiar power system which the present invention uses to feed the large quantity of power required within the formation to make the operation viable. The Neutral in one layout is solidly grounded, allowing it to serve as the first production outlet around and upon which workers may be able to work safely while the power is flowing.

FIG. 6 illustrates the electrical current path of the three-phase arrangement of wells as shown in FIGS. 5 a and 5 b. The typical Phase A, B, C with Neutral are shown for each well in the production unit. Depending on conductivity of the formation and its depth, the spacing between wells may vary quite widely, for example, anywhere between about 20 to about 200 meter spacing. The broken lines 80 represent the current flow between Phase A and B; however, the current flow is similar between each of the other phases and the Neutral. The current flow 80 represents the electrical heating within the formation. As the formation heats where the current flows, gradually this heat will spread out towards its surroundings such that all of the formation is thoroughly heated.

FIG. 7 illustrates one embodiment of a surface distribution layout of a plurality of multi-well production units of the present invention. This configuration allows the minimum number of wells to be used to totally cover the power into the formation. The present invention allows a typical production unit to be spaced as shown on the “top group” to totally heat the formation within the triangles and on outside a small distance. Note the complete electrical separation between the top group and bottom groups. Also note that each separate group has a well in the triangle which matches up with the adjoining triangle production unit such that the area between triangles are all capable of being heated from the same A, B, C phases. Power may be applied between each production triangle unit and may also be connected between the top and bottom groups as well.

The practice of the method of the present invention will be described using the following two-well example. Two substantially vertical wells are first drilled with one drill bit from the surface until reaching the oil sand formation. Drilling is then continued through the oil sand formation with a larger drill bit to form an enlarged cavity down to and several meters or so beyond the bottom of the oil sand formation. This enlarged cavity is the production cavity into which conductive liquid is added to make intimate contact with the oil sand formation. The production cavity also serves as the collection and separation reservoir into which the bitumen flows and later pressure extracted to the surface. Preferably, a plurality of wells are drilled in an arrangement such as shown in FIGS. 5 a and 5 b, whereby each of the wells is spaced about 20 to about 200 meters apart depending on formation conductivity.

Each well is encased with casing as is known in the art. The casing is sealed between the casing and the well bore or drill hole overburden so that the operating pressures that the wells will be exposed to will be contained. Production tubing is then inserted in each well through the well casing. The production tubing is sealed at the surface to seal the production tubing tightly against the formation operating pressure. The production tubing has its own bitumen recovery valve and clean-out valve as shown in the surface wellbore arrangement in FIG. 3.

The electrical conductor with the electrode attached thereto is lowered down through the production tubing of each well and suspended within the production cavity containing the conductive liquid. It should be noted that minimal power is conducted through the wall of the production tubing; hence the power loss is negligible in getting from the surface to the formation. Each well comprises a surface arrangement for sealing off the well during the practice of the present invention.

Initially, each well is sealed off using the surface sealing arrangement. Electrical power at voltages up to 72,000 Volts or more is applied to the electrical conductor in each well such that current is made to flow through the formation from one well to the next. The use of high voltage not only assists in establishing the initial communication through the formation, but it also allows large power input using low amperage. Further, it allows a greater separation distance between wells, making the technology potentially more affordable than those using closely spaced holes.

Without being bound to theory, it is believed that initial conduction is established mainly through the thin film of brackish water encapsulated between each individual sand particle and the outer bitumen layer also surrounding each sand particle (referred to previously as the hydrophilic film). Later, communication is maintained in part through the conductive liquid, which gradually replaces the displaced heated bitumen. The heated bitumen slowly rises upward through the conductive liquid towards the surface of the liquid in a collection cavity.

Maximum flow of power may be achieved by providing a path of least resistance through which the power can flow. The resistance between electrodes is reduced by placing all resistance values, within the formation, in parallel. The resulting resistance is the lowest possible level achievable in the formation. This lowest level resistance is achieved by having a wetting agent added to the conductive liquid in each production cavity, thereby helping the conductive liquid make intimate contact with the oil sand formation. The conductive liquid thereby joins in parallel all of the high and low conductivity levels existing, from the top to the bottom of the formation. With all of these high and low resistance paths in parallel, the final resistance will be a small fraction of what the lowest individual resistance will be. This allows the maximum possible flow of power through the formation at any applied voltage.

The enlarged cavity (i.e., production cavity) is used as a production reservoir into which the heated bitumen flows and from which the bitumen is extracted. The enlarged cavity also serves as the sand/silt reservoir into which the cleansed sand can fall. Finally, it serves as the reservoir into which the bitumen may quietly settle out from the brackish water, sand and silt, allowing more pure bitumen to be extracted. While the current density at the electrode will be highest, the large surface area of the electrode will result in a relatively low watt density to eliminate baking of bitumen that comes in contact with the electrode.

The large reservoir of conductive liquid serves not only to make intimate contact with the formation, but also acts as a heat equalizing coolant between electrode, conductive liquid, and formation. The watt density at the interface of the formation and the liquid is higher than at all points within the formation, as was found from earlier work. This means that the heat generated within the formation will be highest at this liquid-formation interface, and will decrease as the distance into the formation increases. The interface therefore heats up faster than the interior of the formation. This allows the bitumen to become hot at the wall of the cavity first, and slowly rise up through the liquid to float on the liquid surface.

Once the bitumen leaves the formation, it is replaced with conductive liquid. The conductive liquid slowly migrates into the formation, from which the bitumen has flowed, further improving the conductivity and the ability to increase power into the formation. Ultimately, the conductivity between electrodes will mainly be via the conductive liquid. The heat generated from electrical power flowing through the conductive liquid will end up being the main source of heat within the formation.

It is hypothesized that once the bitumen formation is heated above a given temperature the conductive film of brackish water surrounding each sand grain will partly or totally dissipate, thereby interfering with the formation conductivity. To avoid possible loss of conductivity, two precautions may be implemented as follows. First, the conductive liquid can be encouraged to migrate into the formation as quickly as possible, as described above, thereby displacing the bitumen with conductive liquid. Second, the center of the formation may be allowed to heat up more slowly than that which is located nearest the electrode cavity. This makes the low current density within the formation and the high density at the liquid-formation interface automatically achieve these desired results. Achieving a high current density at the cavity-to-formation interface is desirable.

The liquid evaporation problem of concern in earlier electrical power recovery methods is overcome by sealing the well to withstand the resulting pressure generated by the temperature rise in the cavity and formation. The contained high pressure prevents the liquid from evaporating once saturation temperature is reached. As power increases into the formation, the resulting temperature and pressure rise are limited only by the competence of the formation. As previously mentioned, formation temperatures of about 275-300° C. or more are achievable.

As discussed above, FIGS. 2 a to 2 e are a series of schematics illustrating the effect on flow of bitumen as both temperature and pressure increases, thereby leading to the heating of the bitumen in the formation and flow of the heated bitumen into the enlarge portion of the well, i.e., the production cavity. FIG. 2 e illustrates that the conductive liquid can reach a temperature of approximately 300° C. and the pressure in the production cavity reaching 6.9 MPa. Heated bitumen flows from the oil sand formation into the production cavity and the pressure allows the bitumen to flow up through the production tubing to the surface of the well. Thus, the invention does not require the use of electrical pumps to remove the bitumen as the pressure produced by the heat from the electrical power flowing through the formation will allow the bitumen to be extracted using this formation pressure, at any desired well.

Further, the present invention allows the bitumen to be separated from the brackish and conductive liquids within the production cavity at the formation. Sufficient settling time will allow the bitumen to float on top of the liquid in the cavity, from where it may be selectively brought to the surface.

It is understood that high voltage use at an operating site is extremely dangerous without applying all possible safety precautions. Thus, in the present invention, power is applied only when workers are not within the fenced area. The neutral electrode, at each four-hole production grouping, may also be used for production while power is applied to the site, as the neutral is intended to be solidly grounded thereby allowing continual production as needed while power is “ON”.

During start-up, there is a possibility the voltage applied between Phase A and Phase B, as illustrated in FIGS. 6 and 7, may not be sufficient to allow the high level of power to pass between wells, since the initial conductivity may be lower than desired. The present invention allows the voltage across A and B phases to be switched so that phase A will stay on its original well, but Phase B will now be connected to the Neutral which is about 58% of the distance compared to that between Phase A and B. This allows the power to increase more rapidly until the formation has heated and conductivity is established.

While the invention has been described in conjunction with the disclosed embodiments, it will be understood that the invention is not intended to be limited to these embodiments. On the contrary, the current protection is intended to cover alternatives, modifications and equivalents, which may be included within the spirit and scope of the invention. Various modifications will remain readily apparent to those skilled in the art. 

1. A method for recovering hydrocarbons such as heavy oil or bitumen from an underground oil-rich reservoir formation, comprising: (a) providing one or more substantially vertical wells, each well having a bottom portion extending into the oil-rich reservoir formation and each well spaced apart from one another; (b) adding to each well a conductive liquid to substantially fill the bottom portion of each well; (c) inserting an electrical conductor comprising an electrode into each well so that the electrode is at least partially submerged in the conductive liquid; (d) applying electrical power to the electrical conductor at a voltage sufficient to heat the conductive liquid and the oil-rich reservoir formation to a temperature sufficient to heat the heavy oil or bitumen in the oil-rich reservoir formation; and (e) substantially sealing the top of each well to maintain a sufficiently high pressure in each well to prevent evaporation once saturation temperature is reached and to force the heated heavy oil or bitumen to flow into the bottom portion of the well and through the well to the surface of the well.
 2. The method as set forth in claim 1, whereby the bottom portion of each well is enlarged relative to the rest of the well.
 3. The method as set forth in claim 1, whereby the voltage ranges from between about 13,000 Volts to about 72,000 Volts, or higher.
 4. The method as set forth in claim 1, wherein the oil-rich reservoir formation is heated to a temperature of between about 100° C. to about 300° C., or higher.
 5. The method as set forth in claim 1, wherein the pressure in each well is between about 0.1 MPa to about 6.9 MPa or higher.
 6. The method as set forth in claim 1, whereby the saturation temperature is about 250° C. to about 350° C.
 7. The method as set forth in claim 1 further comprising adding a wetting agent to the conductive liquid.
 8. The method as set forth in claim 1, whereby the conductive liquid comprises an electrolyte selected from the group consisting of sulfates, nitrates, acetates, oxalates, bitterns, bromides, and any combination of sulfates, nitrates, acetates, oxalates, bitterns and bromides.
 9. The method as set forth in claim 1, the heated heavy oil or bitumen further comprising brackish water, silt and sand, whereby the heated heavy oil or bitumen rises to the top of the conductive liquid and is separated from the brackish water, silt and sand.
 10. A method for recovering hydrocarbons such as heavy oil or bitumen from an underground oil-rich reservoir formation, comprising: (a) providing one or more substantially vertical wells, each well having a bottom portion extending into the oil-rich reservoir formation and each well being lined with a casing; (b) inserting a production tubing into each well, said production tubing extending at least partially into the bottom portion of said well; (c) adding to each well a conductive liquid to substantially fill the bottom portion of each well; (d) inserting through the production tubing an electrical conductor comprising an electrode so that the electrode is at least partially submerged in the conductive liquid; (e) applying electrical power to the electrical conductor at a voltage sufficient to heat the conductive liquid and the oil-rich reservoir formation to a temperature sufficient to heat the heavy oil or bitumen in the oil-rich reservoir formation; and (f) substantially sealing the top of each well to maintain a sufficiently high pressure in each well to prevent evaporation once saturation temperature is reached and to force the heated heavy oil or bitumen to flow into the bottom portion of the well and through the production tubing to the surface of the well.
 11. The method as set forth in claim 10, whereby the production tubing is moveable so that it can be raised or lowered within the well.
 12. The method as set forth in claim 10, whereby each well is sealed by means of a surface arrangement comprising a valve, said valve having an open and a closed position such that when the valve is in the open position the heavy oil or bitumen can flow through the production tubing and be removed at surface.
 13. The method as set forth in claim 10, whereby the electrical conductor further comprises an insulation jacket suitable for the operating voltage and temperature.
 14. The method as set forth in claim 10, whereby the bottom portion of each well is enlarged relative to the rest of the well.
 15. The method as set forth in claim 10, whereby the voltage ranges from between about 13,000 Volts to about 72,000 Volts, or higher.
 16. The method as set forth in claim 10, wherein the oil-rich reservoir formation is heated to a temperature of between about 100° C. to about 300° C., or higher.
 17. The method as set forth in claim 10, wherein the pressure in each well is between about 0.1 MPa to about 6.9 MPa or higher.
 18. The method as set forth in claim 10, whereby the saturation temperature is about 250° C. to about 350° C.
 19. The method as set forth in claim 10 further comprising adding a wetting agent to the conductive liquid.
 20. The method as set forth in claim 10, whereby the conductive liquid comprises an electrolyte selected from the group consisting of sulfates, nitrates, acetates, oxalates, bitterns, bromides, and any combination of sulfates, nitrates, acetates, oxalates, bitterns and bromides.
 21. The method as set forth in claim 10 further comprising: (g) separately removing any gas from the formation that has accumulated in the bottom portion of the well.
 22. The method as set forth in claim 10, the heated heavy oil or bitumen further comprising brackish water, silt and sand, whereby the heated heavy oil or bitumen rises to the top of the conductive liquid and is separated from the brackish water, silt and sand.
 23. The method as set forth in claim 10, whereby the underground oil-rich reservoir formation is oil sand or oil shale. 